1.Coiled-Tubing Technology(1995-1998) DEA-67 Phase I1PROJECT TO DEVELOP AND EVALUATECOILED-TUBING AND SLIM-HOLE TECHNOLOGYMAURER ENGINEERING INC. 2916 West T.C. Jester BoulevardHouston, TX 77018-7098 Telephone: (713) 683-8227 Facsimile: (713) 683-6418Internet: http://www.maureng.comE-Mail: mei@maureng.com TR98-10April 1998The copyrighted 1998 confidential report is for the use of Participants on the Drilling EngineeringAssociation DEA-67 PHASE II project to Develop and Evaluate Coiled-Tubing and Slim-HoleTechnology and their affiliates, and is not to be disclosed to other parties. Participants and theirFaff~liates free to make copies of this report for their own use. are

2. Coiled-Tubing Technology (1995-1998) TABLE OF CONTENTS ChapterARTIFICIALLIFT ..............................................................1BUCKLING ....................................................................2CEMENTING ................................................................... 3COILEDWBING ............................................................... 4DRILLING ..................................................................... 5FATIGUE ......................................................................6FISHING ....................................................................... 7LOGGING ..................................................................... 8OVERVIEW ....................................................................9PIPELINES .................................................................... 10PRODUCTIONSTRINGS ........................................................ 11-,RIGS .........................................................................12STIMULATION ................................................................ 13TOOLS ....................................................................... 14WORKOVERS ................................................................. 15APPENDIX-Coiled-Tubing References 3. 1. Artificial LiftTABLE OF CONTENTSPage1. ARTIFICIALLIFT . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1-1.1.1 CENTRALIFT AND SHELL EXPRO (CT-DEPLOYED ESP) . . . . . . . . . . . . . . . . . . . . . 1.11.2 HALLIBURTON ENERGY SERVICES (CT ARTIFICIAL LIFT) . . . . . . . . . . . . . . . . . . 1-31.3 SCHLUMBERGER DOWELL (UNLOADING WELLS WITH CT). . . . . . . . . . . . . . . . 1-51.4 SHELL WESTERN E&P (CT C 0 2 GAS LIFT). . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1-91.5 TEXACO. McMURRY-MACCO LIFT SYSTEMS. AND DOWELL (CT GAS LIFT) ..1-91.6 TRICO INDUSTRIES (JET PUMPS). . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ..1 111.7 UNOCAL AND SCHLUMBERGER DOWELL (CT JET PUMP RECOMPLETION) . . 1-131.8 XL TECHNOLOGY (CT DEPLOYED ESPs) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .1.16F 1.9 XL TECHNOLOGY (FIELD EXPERIENCE WITH CT ESPs) . . . . . . . . . . . . . . . . . . . . 1-211.10 REFERENCES . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1-22. OMaurer Engineering Inc. 4. OMaurer Engineering Inc. 5. 1. Artificial Lift1.1 CENTRALIFT AND SHELL EXPRO (CT-DEPLOYED ESP)Centralift and Shell Expro UK (Watkins and Stewart, 1996) described planning and implementinga successful CT-deployed electric submersible pump (ESP) offshore in the Auk field (North Sea). Severalnew tools and procedures were developed for this installation. Various methods were analyzed in thesearch for alternate techniques for deploying ESPs in the field. The first CT-deployed pump was workingwell one year after installation, and a utilization rate of 96% was reported. The conventional method of artificial lift in the Auk field was wireline-retrievable hydraulic jet pumpsinstalled with a rig. Limited capacity in the hydraulic supply system permitted only three wells to be liftedsimultaneously. Shell therefore sought alternate systems for artificial lift. After Shell settled on ESPs, potential deployment methods were investigated. Changing theconventional deployment method would allow a savings of 20% on future workovers, a 50% reduction ininstallation times, and a savings of 100 man-days in bedding. Deployment methods considered were: 1)hydraulic workover rig, 2) cable suspension, and 3) coiled tubing.,-Cable deployment was not suitable due to the wells 74" inclination at depth. CT was determinedto be more economic and better suited to operational experience in the field than a hydraulic workoversystem. New equipment was developed, including high-strength CT connectors to join reels of 2%-in. tubingand to connect completion subassemblies (SSSV etc.). A new packer was designed that could be set andreleased hydraulically. The tubing spool was modified to permit the power cable to exit the wellhead ata right angle (Figure 1-1). This provided amajor cost savings by maintaining the origmal flow-line height.OMaurer Engineering Inc. 6. Figure 1-1. Modified Tubing Spool(Stewart et al., 1996)The ESP downhole assembly (Figure 1-2) included a 280-HP motor. OMaurer Engineering Inc. 7. Sump p r u ra-bhFigure 1-2. ESP Assembly for AukField (Watkins and Stewart, 1996)Platform height restrictions required the fabrication of a special tower frame for supporting thegooseneck and extension. Three stack-up tests were performed with the new equipment, including a fulltrial installation in Aberdeen.12 .HALLIBURTON ENERGY SERVICES (CT ARTIFICIAL LIFT) Halliburton Energy Services (Courville and Clark, 1995) summarized the increased potential of CTfor artificial lift applications, particularly with the advent of larger tubing sizes. CT is clearly well suitedfor use in relatively low-pressure wells in non-hostile environments. ESPs can be deployed on CT, andseveral gas-lift methods are being developed and refined.1-3 OMaurer Engineering Inc. 8. The well-know advantages of CT for production applications include reduced formation damage(underbalanced installation, no pipe dope), improved wellbore integrity (no joints, no leaks), easieroperations (pressure tested at factory, rapid run-in speeds), and lower costs (competitive tubing cost,rigless operations). Disadvantages for production applications include the general undesirability of on-sitewelding, the need to perform hot work outside the well, and the lack of industry experience with large CTwith respect to life and corrosive environments.CT is particularly well suited for deploying ESPs because of the absence of connections. Threadedconnections slow installation and provide a large number of potential cmsh points for the power cable andleak paths for production.ESPs can be deployed on CT with either side-by-side or concentric methods. For the side-by-sidemethod, the power cable is banded to the CT as it is run in the hole (Figure 1-3). f i s method is morepractical and less complex than the concentric method (power cable inside the tubing), except duringinstallation. An advantage of the concentric method is removal of the need to kill the well during theoperation.CT ReelCableWellheadBands that attach and hold electricpower cable to OD of tublngConnector tor attachmentof tubing to the pump1 - Electric Submenlble Pump (ESP) Figure 1-3. CT-Deployed ESP (Coumille and Clark, 1995) 1-4 OMaurer Engineering Inc. 9. Earlier operations deploying ESPs on small CT required only mechanical support from the tubing,that is, the tubing was not used as a flow line. High friction losses inside the CT (Table 1-1) required thatproduction be routed through the annulus. With larger CT, acceptable flow rates are now attainablethrough the CTTABLE 1-1. Maximum Flow Rates for CT (Courville and Clark, 1995)MeasuredMaximum Calculated Flow Rates (BID)Depth Tubing Size (in.)- (ft)1Y41#1% 2 2%2h 3%1.3 SCHLUMBERGER DOWELL (UNLOADING WELLS WITH CT)Schlumberger Dowell (Gu, 1995) presented an analysis of transient flow for operations involvingnitrogen injection through CT for unloading wells. Transient behavior is very important for determiningoptimum nitrogen volume, injection time, injection depth etc. for unloading a well. They used a CTsimulator to investigate these interactions. Tubing OD, workover fluid, nitrogen rate and nitrogen volumewere analyzed with respect to sensitivity on job design. Job costs can be minimized by optimizinginjection rate and time (i.e., minimize total nitrogen volume).For wells where reservoir pressure is sufficient to lift produced fluids after heavier fluids areremoved from the wellbore, a short-term lifting process can be used to unload the well and restore1-5 OMaurer Engineering Inc. 10. production. The composition of the wellbore fluid changes during the unloading operation; steady-stateconditions are not reached until the well is unloaded and production restored.Schlumberger Dowel1 ran several test cases to investigate the interactions of various parameters onthe success of the unloading operation. One parameter is the composition (i.e., weight) of the fluid in thewellbore. The assumed test conditions included a TD of 12,200 ft, 4-in. casing, no tubing, 4700-psireservoir, and 15,000 ft of 1%-in. CT. Nitrogen is injected at a rate of 300 scfm during run-in. At 12,000ft, injection is increased to 600 scfm for 90 r i . Flow rates for this operation are charted in Figure 1-4. nn Figure 1-4. Nitrogen Injection to Unload Well (Gu, 1995)The operation depicted in Figure 1-4 assumes that the wellbore fluid has an SG of 1.O. For theseparameters, the wellbore will be successfully unloaded and begin producing after injection is stopped.However, if the fluid density is assumed to be SG=1.15, not enough fluid will be unloaded to sustainproduction after injection is halted. More injection time would be needed if a heavier fluid is in thewellbore.Another important variable is the impact of reproduced workover fluids. For this analysis, a TD of9030 f?, 2%-in. production tubing to 8500 ft, 4%-in.casing to TD, 3500-psi reservoir, and 15,000 ft of 1%-in. CT were assumed. Nitrogen is injected at 300 scfm and the CT is parked at 8800 ft. Unloading canbe completed in 150 rnin if workover fluid was not lost to the formation. If 50 bbl of workover fluid needsto be produced from the formation, injection time must be increased to about 240 min (Figure 1-5).1-6OMaurer Engineering Inc. 11. Figure 1-5. Unloading with Production of Workover Fluid (Gu, 1995)An assessment of the volume of workover fluid to be produced back from the formation has to beestimated based on previous experience in the field. Upper and lower bounds should be used to designthe unloading operation.- Optimizing injection rate is another important aspect ofjob design. As injection rate is increased,frictional losses in the annulus increase. The drawdown imposed on the formation is a combination ofhydrostatic and fiction pressure at the formation. It is desired to minimize nitrogen volume and injectiontime to minimize job costs. For this analysis, job conditions included a TD of 1 1,050 ft, 27h-in. production tubing to 10,500 ft,4%-in. casing to TD, 2800-psi reservoir, and 13,000 ft of 1 %-in. CT. A constant total volume of 91,500scf was injected. Several nitrogen injection rates were used. At higher rates, friction pressure lowersdrawdown pressure at the formation, and unloading is not successful (Table 1-2). TABLE 1-2. Effect of injection Rate (Gu, 1995) Unloading Results for Different Nitrogen RatesI(CTOD = 1.5 in., N, Volume = 91.500 scf) II1 N, Rate (scfml 3001Stop Time(minl350 1 Unloading OutcomeSuccessful116001 230 1 SuccessfulI19001 190 1~nsuccess~u~ I unsuccessfu~ I1-7OMaurer Engineering Inc. 12. CT size also impacts job success. For the case in Table 1-2, an injection rate of 900 scfin would besuccessful if CT diameter were decreased to 1% inches. Depth of injection is anotherimportant parameter. The model wellfor this analysis had a TD of 10,000 ft,2h-in. tubing to TD, a productivityindex of 0.5 BPDIpsi, and 15,000 ft of 1%-in. CT. Liquid return rate for arange of injection rates is shown inFigure 1-6. For 300 scfin, the liquidrate increases only slightly for injectiondepths greater than 4000 ft. Amaximum practical depth can beestimated for any injection rate.Figure 1-6. Return Rate with 1%-in. CT (Gu, 1995) Running the CT deeper than this maynot provide any added benefits. This depth analysis is of course impacted by CT OD (and annulus size). For smaller CT (1 % in.) inlarger tubing (5-in casing), fiction losses are less important. Higher injection rates can increase unloadingrates without creating significant friction losses (Figure 1-7). Y- ._.-.-...--._.----- .. ............. ....................... ..#. 0.0 Ir________-_____-----__------- I I.,--- lDlk.....-& 0. lD D D a o -- - --51-(11Figure 1-7. Return Rate with 1%-in. CT (Gu, 1995) 1-8 OMaurer Engineering Inc. 13. -. 1.4 SHELL WESTERN E&P (CT CO, GAS LIFT) Shell Western E&P (Sorrell and Miller, 1997) described the design and evaluation of two CO, gas lift installations in the Denver Unit, a mature field in West Texas. The field is now under tertiary recovery with CO, water-alternating-gas (WAG) injection. Costs of the CT applications ranged between $65,000 and $75,000 (Figure 1-8). Figure 1-8. Costs for CO, CT Gas Lift (Sorrel1 and Miller, 1997)?- - More information is presented in Production Strings. 1.5 TEXACO, McMURRY-MACCO LIFT SYSTEMS, AND DOWELL (CT GAS LIFT) Texaco E&P, McMurry-Macco Lift Systems, and Dowell (Tran et al., 1997) described several successful installations of CT gas lift. On-location make up of the gas-lift assembly reduced costs. The completion method has been mechanically and economically successful, and will be applied in other fields. The gas-lift mandrels were installed on-site by cutting the CT as the completion is run in (Figure 1- 9). The crew can perform a tensile test for checking connector and string integrity and a pressure test for the valves and connections. OMaurer Engineering Inc. 14. Figure 1-9. Work Window for Installing G s Lift (Tran et al., 1997)aIn one field installation, a 10,000-ft string of 1%-in. CT was run in the Brookeland Field. Bottom-hole pressure was too low for conventional gas lift. CT gas lift improved daily production (Figure 1-10)and reduced the initial annual decline from 97% to 20%. Installation cost was $60,000. OMaurer Engineering Inc. 15. -TEXACO FEE UNIT I O O l H BAOOKELAND 1:ooooTEXACO AUSTIN CHALK BBOC II Figure 1-1 0. Production of CT Gas-Lifted Well (Tran et al., 1997)Project members found that injection gas requirements were about half that used in conventional gaslift for the same produchon. The cost of the field-fabricated string was less than a manufactured spoolablestnng.16 .TRICO INDUSTRIES (JETPUMPS)Trico Industries (Tait, 1995) enumerated the advantages of jet pumps run on CT for artificial-liftapplications in horizontal and vertical wells. A primary advantage is the lack of moving parts in theassembly. Energy is provided to the jet pump by pumping power fluid from the surface (Figure 1-1 1). Thepower fluid may be produced oil or water, treated sea water, diesel , or other fluids. The primaryadvantages of jet pumps are a wide range of flow rates, deep lifting capacity, and the ability to handle fluidsthat have high sand concentrations, are corrosive, are at high temperatures or have significant free gas. OMaurer Engineering Inc. 16. - ADJUSTABLE CHOKEdTO SYSTEM FACILITIES 2 CONNECT & OISCDNIECT1JET P U N!TUBING FACERIiFigure 1-1 1. Jet Pump for Unloading Wells (Tait, 1995) Lifting action is provided by energy transfer between the power fluid and the wellbore fluid Highpotential energy in the pressunzed power fluid is converted to kinetic energy as the fluid passes througha n o d e (Figure 1-12). A low-pressure zone is created in the throat, and the wellbore fluid is drawn intothe power stream.POmRFLUIDPRESSUREPOWERFLUIDVELOCITY ------NO=THROAT DIFFUSERFigure 1-12 Jet Pump Operahonal Pnnc~ple (Tart, 1995) 1-12OMaurer Engineering Inc. 17. h Jet pumps have been used since the 1970s for long-term artificial-lift applications around the globe.These can be sized for production rates ranging from 50 to 15,000 BPD at depths exceeding 15,000 ft. Trico Industries described the use of a jet pump run on CT for production testing of horizontal wells.The pump can be run as a free pump (Figure 1-13), circulated into and retrieved from the well via thepower fluid. This system can be used along with downhole pressure recorders to obtain inflowperformance data in a production rate step-test procedure.Figure 1-13. Free Jet Pump for Horizontal Production Testing (Tait, 1995)1.7 UNOCAL AND SCHLUMBERGER DOWELL (CT J E T PUMP RECOMPLETION) UNOCAL and Schlumberger Dowel1 (Hrachovy et al., 1996) described the design process,installation, and results of a CT recompletion of two wells in Alaskas Cook Inlet fields. Several remedialoptions were compared for these wells. The most economic approach was to run a ]%-in. jet pump at thebonom of a string of 1%-in. CT. Produced fluids and exhausted power fluids were produced through theannulus between the CT and 3 %-in. production tubing. Total costs for the first two wells were $220,000and $120,000, significantly lower than other options considered.The most common existing completion in this area of Cook Inlet includes a piston pump in a 3-in.cavity hung from dual 3%-in. production strings inside 96/e-in. casing (Figure 1-14). Piston pumps aregenerally preferred due to higher efficiencies. Two wells, one on the Anna platform and one on the Baker,had been shut in due to problems with downhole hydraulic power fluid equipment. High costs forconventional workovers made shut-in necessary. OMaurer Engineering Inc. 18. KB -105 MSL 20 CSG @ 622I3-90. CSG g 2022L 1Long String: 3-112" ~ u t tShon Stvlng: 3-112" Butt-8.41 0-78389.3 101627- Collad Tubing :OD 10 1.532" QT-7001.76" CowTIMnp- 2.20 Triw Jel Pump Csvity WI 1.0s Je( Halliburlon 3-112TBG Packer H.Yurtn 1C S d Ba Ennlla r *I* s b G~ l l r X I.IIC XO 0 7 The3 KOBE 8 L-285 Pump Cavity7 Liner Top @ 8004O-5WCSGO WPans: 8ZlU186Pd.: UQrdYIPYh:M61T47*(M c 807S.PXIIPMc w-lO.LYSPBTO. 10.310 Figure 1-14. Anna 26 Completion~Recompletion(Hrachovy et al., 1996)Inflow performance ratio (IPR)curves were prepared (Figure 1-15) to evaluate the performance ofvarious recompletion options to bring the wells back on line. OMaurer Engineering Inc. 19. 0100YW ,m 4W5m 000 0 BOPD Figure 1-1 5. Anna 26 IPR Curves (Hrachocy et al., 1996)Three completion options were considered: 1) a conventional workover including pulling thecompletion with a rig or jaclung unit and running a new dual completion, 2) pull the completion and runF a single 4%in. production string with a concentric 2h-in. CT string, or 3) run 1%-in. string of CT insideone of the existing 3%-in. production stnngs.The h t option (anew dual completion) was not pursued due to hlgh estimated costs ($850,000) andlack of availability of a suitable rig. The second option (a new concentric production string) wastechnically the best because the pump could be placed deeper and improve the drawdown. Cost estimateswere even higher for option 2 ($925,000) and the same scheduling problems were pertinent.The thnd option was deemed the best compromise. A jet pump could be run on CT and productiontaken up the CT by production tubing annulus. The incremental production from options 1 or 2 was notsufficient to ovemde higher costs and greater installation risks. Future workovers with option 3 could alsobe accomplished with a CT rig, thereby improving overall economics. Costs to recomplete the two wells are summarized in Table 1-3. The pre-job cost estimate was$184,500 for the Baker 20 and $175,000 for the Anna 26. Several problems during field installationincreased the cost of the Baker 20. Lessons learned on the first lead to cost savings on the Anna 26($54,500 below budget).OMaurer Engineering Inc. 20. TABLE 1-3. Recompletion Costs (Hrachovy et al., 1996)1 Item1Baker201 Anna 2611 Coiled-Tubing Unit Rental$75,000$40,000 1 1%-in. Tubing Purchase 10.000 10,000Wellhead45,000 3 1,0001 PackersI26,000113,000 11 Perforating I Wireline I23,0001 6,100 1Logistics I Misc. 22,000 16,2001 Supervision 14,0004,2001 Total $215,0001 $120,5001Production performance of the Anna 26 is shown in Table 1-4. UNOCAL believes that thedifference in production from predicted rates is due to incorrect assumptions in deriving the IPR curve. TABLE 1-4. Recompletion Performance (Hrachovy et al., 1996)III I1 Item (Anna26 Anna 2 6 111Predicted 1 Actual1Power Oil Consumed, BOPD 1250Power Oil Pressure, PSlG 2450 , 3500 1Produced Oil, BOPD I240 11201 I1 Produced Water Cut,% I 40 1 7 1Gross Fluid Production, BFPD400400Pump Intake Pressure, PSlG7954901.8 XL TECHNOLOGY (CT DEPLOYED ESPs)XL Technology Ltd. (Tovar and Head, 1995) described the development and benefits of a new CT-deployed ESP system. This effort represents a joint-industry project ("Thennie") funded by the EuropeanCommission and several operators, service companies and manufacturers. The primary innovation is thatthe power cable is placed inside the CT, allowing rapid installation and deployment in live wells. Twofield tests were conducted to demonstrate the efficiency of thls method. Total estimated cost savings withthis approach are over 40%, including a 20% reduction in equipment costs and 3 to 4 fewer days on site. 1-16OMaurer Engineering Inc. 21. Basic equipment configuration of the ESP with internal power cable is shown in Figure 1-16.Downhole components include the CTIcable assembly, subs for pressure insolation and circulation, andSSSVs. The number of electrical connections is reduced from four with an external cable to two with aninternal power cable. Additionally, the power cable is isolated from pressurization/depressunLation cycles.51 U n n a m rC I I POW r m aCT Un-rObmrgl U d8nlI)urn@)urn@mmpYmml Figure 1-16. ESP Design (Tovar and Head, 1995)Procedures for deploying the system in a live well are illustrated in Figure 1-17. Complete live-welldeployment was simulated in the field tests.OMaurer Engineering Inc. 22. Figure 1-17 . Live ESP Deployment (Tovar and Head, 1995)The &st field ma1 (Table 1-5) was onshore in Southern England in the Stockbridge Field to a depthof 3200 ft and deviation of 40". The second well test was to 2900 f and 50" deviation. Based on thesetsuccessful operations, it is estimated that deployment speeds of greater than 50 ftimin are achievable TABLE 1-5. ESP Test Summary (Tovar and Head, 1995) , Information Well No. 101 well NO. 5 1Date of the testPressure deploymentBHA length79 feet 79 feetRiser length90 feet N/ABHA deployed withWirelineCrane I Operational time( 33 hours 1 14 hours 1Run in speed 24 f t per min 29 f t per min1-18 OMaurer Engineering Inc. 23. Four primary options were identified for deploying ESPs (Table 1-6): conventional tubingdeployment, running on CT with external power cable, cable-deployed pumping systems, and running onCT with internal power cable.Costs are compared based on a deployment depth of 5000 ft TABLE 1-6. Options for ESPs in North Sea (Tovar and Head, 1995)FeatureISystemConventional CTCable Deployed CTTubingExternal Cable Pumping S y s t e m Internal CableDepth L i m ~ t sNone NoneNone NoneDeviation Limits None None59 degrees No.neMax Tubina Size 7.0" 3%N /A N /A I-Min. C a Z S i z e~1 1N/ANIA I7.0" 7 4%" IFlow Path Internal Tbg.Internal CT Internal C s g f l b g Internal C s g f l b gI I Iate Limitation1NO 1Yes 1No1 No 1 1Well Control CapacityNone None INoneI YesI 1Cable ProtectionINone None INone1 YesISpecial Pump Reqd. NoNoYes NoReservoir MonitoringY es YesNoYesCorrosive FluidsYesLimitedNoLimited 1 C o m ~ r e s s i o n ~ D e c o m ~ .1 Yes 1Yes 1 Yes1NoI L a b ~ splicing e1 yes 1yes I YesI Y es I INo. Cable Connections 14I 4 I 2i 2IWell Intervention Y es Y es NoYesEquipment RequiredRigCT UnitSpecial Unit CT Unit1-19OMaurer Engineering Inc. 24. I Avg. Equipment Cost 66.8 Slft1 70.0 Slft 1 91.0 Slft50.0 Slft1I Avg. Service Cost145.5 S l f t 1 20.5 Slft 31.3 Slft 114.2 S l f t 1 Average Workover Time 8 days 6 days4 days 4 days I I I II Subsea Application 1No 1NO 1No I Yes I HSE ApprovedYes YesNo YesTime requirements for a CT deployment with internal power cable are 3 to 4 days less thanconventional and 2 days less than CT with external cable. Total estimated job costs are compared inFigure 1-18.Figure 1-1 8. ESP Costs in North Sea (Tovar and Head, 1995)XL Technology Ltd. believes that the new ESP deployment system shows great promise. Anotherarea where this technology might be applied is running electric drills. This drilling technique is wellestablished in the FSU, but relatively unknown in the West. Additional study is undeway to investigatethe feasibility of this application. 1-20 OMaurer Engineering Inc. 25. /C41.9 XL TECHNOLOGY (FIELD EXPERIENCE WITH C T ESPs) XL Technology (Cooper and Head, 1997) presented an update of their work with CT-deployedelectric submersible pumps (ESPs). These installations are proving to be well suited for installation inremote areas including offshore and areas with minimum facilities. The system was originally conceivedto allow rigless completions that include ESPs. Several months of production experience have shown thatthe system is a viable completion option. Additional improvements might be added to the system, and itis foreseen that the installation time could be reduced to 14 hrlwellThree components comprise the complete system: the ESP assembly (Figure 1-19), the CT stringwith power cable inside, and the tubing hanger. Production is through the CT by production tubingannulus. The power cable is preinstalled in the CT and supported by aCoiled tubingseries of anchors at regular intervals. During installation, it was discovered that aligning the CT to motorBunt discconnection was more difficult than anticipated A more versatileconnector was designed (Figure 1-20) to allow quick connection on theCoikdNbing to motorconnectorrig floor.Motor sectionM o l n sectionDischarge headFigure 1-19. ESP Assembly(Cooper and Head, 1997)OMaurer Engineering Inc. 26. Figure 1-20. Quick Connect for CT to Motor (Cooper and Head, 1997)1.10 REFERENCES Cooper, R and Head, P., 1997: "Coiled Tubing Deployed ESPs Utilizing Internally Installed PowerCable - A Project Update," SPE 38406, presented at 2"*North American Coiled Tubing Roundtable,Montgomery, Texas, April 1-3. Courville, Perry W., and Clark, Thomas R, 1995: "Coiled Tubing Completions: An EconomicDiscussion of Procedures," SPE 29781, presented at the Middle East Oil Technical Conference andExhibition, Bahrain, March 1 1-1 4. Gq H., 1995: "Transient Aspects of Unloading Oil and Gas Wells With Coiled Tubing," SPE 29541,presented at the Production Operations Symposium held in Oklahoma City, Oklahoma, April 2-4. 1-22 OMaurer Engineering Inc. 27. P.Hrachovy, M. J., et al., 1996: "Case History of Successf~~l Coiled Tubing Conveyed Jet Pump Recompletions Through Existing Completions," SPE 35586, presented at the SPE Western Region Meeting held in Anchorage, Alaska, May 22-24Sorrell, Dean, and Miller, Ron, 1997: "Coiled Tubing CO, Gas Lift Evaluated in West Texas," World Oil, January.Tait, Howard, 1995: "Coiled Tubing Jet Pump for Extended Reach Horizontal Well Cleanups," presented at the Third Annual Conference on Emerging Technology - CT-Horizontal, Aberdeen, Scotland, May 31 - June 2.Tovar, Juan J., and Head Philip F., 1995: Technical and Economic Considerations for CT Deployed ESP Completions," presented at the Third h u a l Conference on Emerging Technology - CT-Horizontal, Aberdeen, Scotland, May 31 - June 2.Tran, T.B. et al., 1997: "Field Installed Coiled Tubing Gas Lift Completions," SPE 38404, presented at 2 " d N ~ r tAmerican Coiled Tubing Roundtable, Montgomery, Texas, April 1-3. hWatkins, Paul, and Stewart, David, 1996: "Coiled Tubing Deployed ESP Works Well for Shell in North Sea Field," World Oil, June.e OMaurer Engineering Inc. 28. OMaurer Engineering Inc. 29. .2 BucklingTABLE OF CONTENTS Page2 . BUCKLING . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .2-1 . 2.1 BJ SERVICES (FEASIBILITY OF TITANIUM CT) . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-1 2.2 CONOCO AND ARC0 (DRAG REDUCER FOR HYDROCARBON FLUIDS). . . . . 2-1 2.3 NOWSCO UK AND STATOIL (DEPLOYMENT OF LONG BHA). . . . . . . . . . . . . . . 2-4 2.4 PEI (CT STRAIGHTENER). . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .2-6 2.5 SCHLUMBERGER DOWELL (EXTENDING CT REACH (PART 1)) . . . . . . . . . . . . 2-6 2.6 SCHLUMBERGER DOWELL (EXTENDING CT REACH (PART 2)). . . . . . . . . . . 2-12 2.7 SCHLUMBERGER DOWELL (FLUID FLOW AND CT REACH) . . . . . . . . . . . . . . 2-16 2.8 UNIVERSITY OF TULSA. NIPER-BDM AND PETROBRAS (BUCKLING MODEL)2-18m 2.9 WELLTEC (WELL TRACTORS) ........................................2-21 2.10 REFERENCES ....................................................... 2-25 OMaurer Engineering Inc. 30. 2-ii OMaurer Engineering Inc. 31. 2. Buckling2.1 BJ SERVICES (FEASIBILITY O F TITANIUM CT) BJ Services (Christie and Gavin, 1997) analyzed the feasibility of using titanium CT for routineapplications offshore in the North Sea. The driving force behind the study is potential weight savings thatmight offset increasingly downrated deck and crane capacities on North Sea platforms. BJ Senicesperformed a series of modeling simulations to analyze the capability of titanium strings to maintainsdticient WOB to push heavy BHAs downhole. Data from actual jobs performed with steel CT were usedas the basis for the simulations. Results showed that titanium may have difficulty in these applications dueto a lower Youngs modulus.In one horizontal well, the surface weight indication would be significantly less for titanium than wasmeasured for steel (Figure 2-1). Less surface weight means a lower hanging weight and less weightavailable to push the BHA into the horizontal section. Compounding the problem is the higher hctioncoefficient obse~ved titanium on steel as compared to steel on steel. fcr 1 ~~~~ -jmo lornZm oawwooam 7mos mwooimoct q a a ~moc ium lam1 IDepth (feet)I- - - -Comm4#orulCT rtanlum CT -+- 81an1m Frict~onLock ---Conl.em~ofelFncllon LockFigure 2-1. Modeled Surface Weights for Steel and Titanium CT (Christie and Gavin, 1997)More discussion on this comparison is presented in Coiled Tubing.2.2 CONOCO AND ARCO (DRAG REDUCER FOR HYDROCARBON FLUIDS)Conoco Specialty Products and ARCO Alaska (Robberechts and Blount, 1997) reported thedevelopment and testing of a new drag-reducing additive for hydrocarbon-based CT applications. Highpressures in CT pump operations to achieve high flow rates have the dual disadvantages of exceeding thecapacity of surface pumping equipment and of reducing CT fatigue life. Drag reducers for water-base2-1OMaurer Engineering Inc. 32. operations have proven very successful at the North Slope. Prior to this work, a drag reducer for additionto hydrocarbons was not available. A new dispersed-polymer drag reducer was formulated and tested withsuccess.Tests were conducted of a variety of drag reducers (Figure 2-2).7 to Triplrr Purp in CTUFigure 2-2. Drag Reducer Test Equipment (Robberechts and Blount, 1997) The new Aqueous Suspension Drag Reducing Additive (AS DRA) has been found to be effectivein batch-mixed operations (Figure 2-3). The additive is also available in low freeze-point suspensions forharsh areas such as the North Slope.OMaurer Engineering Inc. 33. Measured pressure drop versus AS DRA concentration w s analyzed (Figure 2-4). Field experienceashowed that batch-mixed fluids can provide significantly more drag reduction than if treated downstreamof the centrifugal pump.These AS DRA additives have proven to be highly cost-effective for CT operations with hydrocarbonfluids.OMaurer Engineering Inc. 34. 2.3 NOWSCO UK AND STATOIL (DEPLOYMENT OF LONG BHA) Nowsco UK Ltd and Statoil (Engel and Sehnal, 1996) developed and implemented a tool-stringdeployment system for running 140 m (459 ft) of perforating guns along a horizontal section. The well (B-15) was located in the Nonvegan sector of the North Sea. A recompletion was planned to isolate a lowerproducing interval (due to high GOR) and perforate a higher interval. Rathole for dropping the guns wasnot available. Drag was a si@cant concern in the well, and friction was reduced by adding rollers to theBHA and using friction reducers. Field operations, including deploying, running and recovering theperforating guns, were completed successfully in 5% days.The deployment system included male and female connectors (Figure 2-5) for quick connectionwithin the surface lubricator. OD is 2.5 inches. Make-up length of the assembly is 972 mrn. Gate valvesprovide double-barrier isolation.Figure 2-5. Deployment System Connectors (Engel and Sehnal, 1996)The surface equipment for deploying long BHAs includes the deployment BOP and isolation gatevalves. A secondary annular BOP was required below the deployment rams (Figure 2-6). QMaurer Engineering Inc. 35. 4 1116 to 7 3 11S xever 4 " quick connect4 1116"to 7 1116" xevarBlind 1 shear ramPlpe ramSlip rnrnPump in tee4 1/16" to 7 1116" x-overUpper Gate valveLower Gate valves 118 to 4 1116" xever4 1116 t~ 5 118- xsvcr "Guide 1 rack ramsNo Q O 1 lock ramspip- ramPipe 1 slip tarns4 1116" to 7 1116" x-overSafely haad8 x 1 56 to RX 46 x-over Figure 2-6. Surface Equipment for Deploying Long BHAs (Engel and Sehnal, 1996)Extensive modeling of drag was conducted prior to the job. The hanging weight of the BHA wasover 2500 kg; 2-in. CT was specified. Rollers were to be added at each joint of the guns. These had beenfound to reduce required pushmg forces by 50%. A drag reducer was also planned to ensure that targetdepth was reached.Drag predictions and results are compared in Figure 2-7. Nowsco stated that the difference betweenpredictedlmeasured POOH weights is explained by gun debris or by low gun weights used in the model.OMaurer Engineering Inc. 36. Figure 2-7. Weight Indication During Operation (Engel and Sehnal, 1996) Nowsco advised that deployment systems similar to the one described are viable options when morethan three separate trips are required to achieve the same objective with conventional deployment methods.Additional information is presented in Tools2.4 PEI (CT STRAIGHTENER) Petroleum Englneer Internat~onal(PEI St&, 1996) presented a description and some early resultsacheved by Schlumberger Dowel1 using a new straightener for CT. The deslgn is based on a three-pointbendlng fixture that is mounted between the gooseneck and injector.In one field well, the string locked up at 13,400 ft MD. The same string was then run with astraightener installed. A sleeve at 13,750 was reached and shifted without problem.2.5 SCHLUMBERGER DOWELL (EXTENDING CT REACH (PART 1))Schlumberger Dowel1 (Bhalla, 1996) presented an analysis of the benefits of various methods toincrease the reach of CT in horizontal and deviated wells. Methods to reduce CT buckling includeincreasing buoyancy of the CT, pumping friction reducers, optimum taper designs, larger OD of CT,removing residual bending, using downhole tractors, pumping fluid, and pump-down systems. Thesemethods, either singly or in combination, can be used to substantially increase reach when appliedappropriately.Extended-reach technology has seen rapid development in the UK and Norwegian sectors of theNorth Sea. Some wells (Gullfaks and Statfjord) cannot be serviced with standard CT operations. Newtechniques and procedures have been refmed for these applications. 2-6OMaurer Engineering Inc. 37. r- Schlumberger Dowel1 simulated the impact of a variety of techniques to reduce buckling and increase penetration in these wells. The example well used in the simulations is shown in Figure 2-8. Figure 2-8. Example Well used for Buckling Simulation (Bhalla, 1996) One technique used at Wytch Farm is pumping friction reducer. Reductions in friction coefficient of up to 15% have been achieved. The impact of friction reducers on surface loads for R H is shown inI Figure 2-9. Lock-up of the CT is expected at a depth of 10,849 ft. An additional reach of 200 ft is predicted for a 5% reduction in friction factor. Over 2000 additional feet of penetration can be achieved by reducing friction factor by 35%. 2-7OMaurer Engineering Inc. 38. M u u d Dcph o Tool Smn;f- ftFigure 2-9. Impact of Friction Reduction (Bhalla, 1996)Tapered CT strings can be used for extending penetration. Thicker pipe is placed in areas ofmaximum compression forces. Taper design 3 (based on 1%-in. tubing) in the example well allows apenetration to 11,600 ft (Figure 2-10). Taper 4 (based on 2%-in. tubing) reaches to 13,800 ft.1 Measured Depth of Top of Tool String - tfl Figure 2-10. Penetration with Tapered Strings (Bhalla, 1996) Residual bends in CT have an adverse impact on penetration limits. The injector constrains CT tobe straight while in the chains, but does not completely unbend the tubing. Schlurnberger Dowel1 measuredresidual bending radii on new 1W-in. 70-ksi tubing (Table 2-1). The reel radius was 58 in.; gooseneckrahus was 72 inches.2-8 OMaurer Engineering Inc. 39. TABLE 2-1. Residual Bends in 1%-in. CT (Bhalla, 1996)Residual Bend Radius Reel t o Gooseneck227.9" (1 8.9f t l Gooseneck t o Injector 102.8"18.6f t l After Injector252.5"(21.0t ) f These tests demonstrated that CT enters the well with a bend radius of 21 ft. Since this bend willhasten the onset of helical buckling, removing this bend will increase penetration limits. Calculations forthe example well (Figure 2-1 1) show that reach will be increased from 10,849 ft out an additional 2153ft with straightened CT. Figure 2-1 1. Surface Weight with Straight CT (Bhalla, 1996)The disadvantage of using a straightener to increase CT reach is an increase in fatigue. Theadditional bending reduces cycle life (Table 2-2). To enjoy the predicted additional reach of 2153 ft, areduction in cycle life of 15 to 23% for the coil will be forfeited. Thus, an economic decision is requiredwith respect to the use of a straightener.OMaurer Engineering Inc. 40. TABLE 2-2. CT Life with Straightener (Bhalla, 1996) Pressure (psi) ) Cycles WithoutCycles With1Straightener Straightener Well tractors are another approach for increasing penetration (see Welltec Section 2.9). The benefitof a tractor was modeled by applylug a range of loads to the BHA. Predicted surface weights are comparedin Figure 2-12. A tractor force of 100 lb on the BHA will increase reach by 201 ft. A pull of 2000 Ib willincrease reach by 455 1 ft. Figure 2-12. Increased Reach with Tractor (Bhalla, 1996) Flow in the annulus can push or pull the CT due to hydraulic friction forces. Calculations showedthat a additional 200 ft of reach can be attained by pumping water down the annulus in the example well.nReach is decreased by 100 ft if water is pumped up the annulus. Generally, the benefits from pumping aresmall (Figure 2-1 3), but may be important in certain critical situations.OMaurer Engineering Inc. 41. mcm I Figure 2-13. Impact of Flow on Reach (Bhalla, 1996)A combination of these types of techniques can be used to maximize penetration limits for CT reach.An additional 15,000 ft of reach can be attained by increasing buoyancy, reducing friction, optimizing taperFdesign and straightening the tubing (Figure 2-14).-M e U d Deplh d Tad Suing 11Figure 2-14. Combined Techniques for Extending Reach (Bhalla, 1996)The additional reach with these combinations is summarized in Table 2-3. It should be noted thatthe effects of each individual technique are not linearly additive. 2-1 1 OMaurer Engineering Inc. 42. TABLE 2-3. Reach with Combined Techniques (Bhalla, 1996) Well 1 Lockup (ft) Well 1 Additional Reach (ft) 1No Technique10,849Buoyancy Reduction & Friction Reducer 13,1022.253Buoyancy Reduction, Friction Reducer20,1016,999& Optimal TaperBuoyancy Reduction. Friction Reducer, 25.0004,899Optimal Taper & Straightening2.6SCHLUMBERGER DOWELL (EXTENDING CT REACH (PART 2))Schlumberger Dowell, Amoco EPTG, and Techad (Lelsmg et al., 1997) continued thelr analysis ofthe potential of various techmques for extending the reach of CT in extended-reach wells. A variety oftechmques were considered (Table 2-1) wth respect to problems, costs, risks, and potential benefits. - Table 2-1. Techniques to Extend CT Reach (Leising et a]., 1997) TechniqueField ProvenCost Potential - -Larger CT or smaller lineryesrned. highM u d lubricant yesmed.lowTubing straightener yeslow low 1 Hole optimizationI yesI low I rned. IUnderbalanced drillingyeshighrned.Bumper subyeslow rned. I EqualizerI yesI low 1 rned. 1 1 Tractorllocomotive 1noI highI high1Slant wellyeslow lowAbrasivelwater jet drillingnomed.Med.RotatornohighhighComposite CT nohighlowII ICounter rotating bit nohighhighA bumper sub (Figure 2-15) provides a WOB that is proportional to differential pressure across thetool. The disadvantages of this type of tool are that 1) WOB is increased as the motor starts to stall, thereby 2-12OMaurer Engineering Inc. 43. aggravating the stall (that is, a positive feedback loop) and 2) open area in the tool and differential pressuremust be matched to achieve the desired WOB. Figure 2-15. Bumper Sub Thruster (Leising et al., 1997)Schlumberger Dowel1 developed and tested a weight-on-bit (WOB) equahzer. It is designed toprovide a constant WOB regardless of friction (Figure 2-1 6).OMaurer Engineering Inc. 44. Figure 2-1 6. WOB Equalizer Response (Leising et al., 1997) The tool (Figure 2-17) is not designed to reduce shock, but rather to provide a constant WOBregardless of sticklslip and variations in motor pressure. The primary disadvantage noted by Dowel1 issimply the additional length added to the BHA. OMaurer Engineering Inc. 45. Figure 2-1 9. WOB Equalizer (Leising et al., 1997)The WOB equalizer assembly is essentially a shock sub with a low spring constant. A chamberwithin the sub is precharged with nitrogen to provide the desired weight.Of the best techniques to increase CT reach (larger CT, smaller liner, thin CT in the horizontalsection, mud lubricants, underbalanced drilling, WOB equalizer, and a rotator), the highest ROPperformance was obtained with the WOB equalizer. It was also the easiest system to drill with, and2-15 OMaurer Engineering Inc. 46. required very little intervention from the surface. While the sub does not in itself extend drilling reach, itincreased ROP and resulted in more efficient penetration.27 .SCHLUMBERGER DOWELL (FLUID FLOW AND CT REACH)Schlumberger Dowell (Bhalla and Walton, 1996) analyzed fluid flow inside CT and the annulus topredict its effect on penetration limits. Their analytical model showed that 1) fluid flow doun (or up) theCT itself had no impact on achievable reach, 2) upward flow in the annulus decreases reach, and 3)downward flow in the annulus (i.e., reverse circulation) increases reach.Theory for accounting for fluid hydraulics and shear stresses (Figure 2-18) was developed andincorporated into their tubing forces model. Any fluid rheology can be evaluated in the assumed concentricannulus. Figure 2-18. Shear Stress from Fluid Flow (Bhalla and Walton, 1996) In one example case, a commercial well profile was evaluated (Figure 2-19). The ratio of MD toTVD is 2.28. The completion included 4%-in. production tubing. The modeled CT string was 1%- by0,109-in. wall.2-16 OMaurer Engineering Inc. 47. Figure 2-19. Example Well Profile (Bhalla and Walton, 1996)Results for the example well showed that lock-up is expected at a depth of 10,850 ft (Figure 2-20).If water is pumped down the annulus at 2 bpm, an additional 500 ft (4.6%) of reach is expected. If wateris pumped up the annulus, reach is decreased by about 400 ft (3.8%). Bhalla and Walton noted that theseresults are based on the assumption of an concentric annulus (centered CT). Tubing will most likely bemeccentric, leading to a decrease in friction pressure. These results should thus be considered a worst-caseprediction.Figure 2-20. Penetration in Example Well (Bhalla and Walton, 1996) 2-1 7 OMaurer Engineering Inc. 48. Fluid rheology can be designed for specific field applications to increase CT reach, or to minimizethe impact on reach.2.8 UNIVERSITY OF TULSA, NIPER-BDM AND PETROBRAS (BUCKLING MODEL) The University of Tulsa, NIPER-BDM, and Petrobras (Miska et al., 1996) described an improvedb u c h g model for transmitting axial force through CT in straight inclined wellbores. They considered thestable sinusoidal region above the critical buckling load. Case studies and experimental verificationdemonstrated the usefulness and limitations of the model.Their anal@cal model is summarized in Table 2-4. They defined a region of unstable sinusoidalbuckling immediately prior to the initialization of helical buckling.TABLE 2-4. Critical Forces for CT Buckling (Miska et al., 1996) Axial Compressive Force Coiled Tubing ConfigurationEIw sin aStraight F 1 "1 2,Anr"~%t!oiled Tubing Inspection and Monitoring System," SPE 38415, presented at 2ndAnnual %..SPE@&A North American Coiled Tubing Roundtable, Montgomery, Texas, April 1-3.Charlie, 1996: "Coiled Tubing Butt Weld Recommendations," The BrieA February. R. et al., 1996: "Development of HPHT Coiled Tubing Unit," SPE 35561, presented atEuropean Production Operations Conference, Stavanger, April 16-17. * -21 8Newman, K.R. et al., 1996: "Analysis of Coiled Tubing Welding Techniques," ICOTA 96007,presented at 1" Annual SPEACOTA North American Coiled Tubing Roundtable, Conroe, Texas, February26-28.Newman, K.R. et al., 1997: "Elongation of Coiled Tubing During Its Life," SPE 38408, presentedat 2"dAnnual SPEIICOTA North American Coiled Tubing Roundtable, Montgomery, Texas, April 1-3. Palmer, R. et al., 1995: "Developments in Coiled Tubing BOP Ram Design," OTC 7876, presentedat 27h Annual OTC, Houston, Texas, May 1-4.Rosen, P.M.A., 1997: "Coiled Tubing Integrity Monitoring During Operations," World O li,December.OMaurer Engineering Inc. 238. -,Robberechts, Hilde and Blount, Curtis, 1997: "A New Generation of Drag Reducer AdditivesHydrocarbon Based CT Applications," presented at 5thInternational Conference on Coiled Tubing andWell Intervention, Houston, February 4-6.Sas-Jaworsky, A., 1996: "High-Pressure Applications Enabled by CT Advances," The American Oil& Gas Reporter, January. Stanley, R.K. 1997: "Failures in Coiled Tubing," presented at 5h International Conference on CoiledTubing and Well Intervention, Houston, Texas, February 4-6. Tipton, Steven M., 1997: "Surface Characteristics of Coiled Tubing and Effects on FatigueBehavior," SPE 3841 1, presented at 2"* Annual SPEOCOTA North American Coiled Tubing Roundtable,Montgomery, Texas, April 1-3.i2.T@hb2 Steven M. 1997: "Low-Cycle Fatigue Testing of Coiled Tubing," presented at 5h onference on Coiled Tubing and Well Intervention, Houston, February 4-6.richem, W.P. et al., 1995: "Development and Utilization of a Coiled Tubing Equipmentpackage for"Work in High Pressure Wells," OTC 7874, presented at 27" Annual OTC, Houston, May 1-4. OMaurer Engineering Inc. 239. OMaurer Engineering Inc. 240. 7. Fishing TABLE O F CONTENTS Page7. FISHING . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .7-17.1 AMOCO TRINIDAD OIL COMPANY (RECOVERING SLICKLINE). . . . . . . . . . . . . 7- 17.2 BRITISH PETROLEUM (CT FISHING TOOL) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7-57.3 VIBRATION TECHNOLOGY (METHOD TO UNSTICK CT) . . . . . . . . . . . . . . . . . . . 7-67.4 REFERENCES. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7-8OMaurer Engineering Inc. 241. OlVlaurer Engineering Inc. 242. 7. Fishing7.1 AMOCO TRINIDAD OIL COMPANY (RECOVERING S L I C K L M ) Amoco Trinidad Oil Company (Forgenie et al., 1995) used CT to perform a strip-over operationof a slickline fish. The modified approach eliminated the risk of recovering the wire piecemeal usingconventional wireline methods. Cost savings were considerable, if it is assumed that wireline operationswould not have been successful.The subject well is located in the Samaan field offshore Trinidad. Slickline operations were beingused to recomplete the well. A problem arose when a shifting tool became stuck in a nipple profile. After unsuccesshl jarring, efforts were made to unlatch from the shifting tool. Two cuttingdevices (go-devils) were attached to the stuck wire and dropped in the hole. Neither reached the tool.Later, the slickline parted near the surface and fell in the hole (Figure 7-1). -2Go-Devib 4 112 Tublng wi*ldld not Reach Fish) Gasllft Mandrels 60 Maximum Wallbore DeviationDSW of 0.108 Sllckllna2UL Sand Perfm -9340 84152 74 Blast Joinh u-Isolation packerD-2 Shlhlnp loo1 wlthsfam, rope aockaf Mechanical RelearTall Pipe with Bull Plug -5.222 Sand Parh -8520 9570 7@ 10465 PBTD 10583 Figure 7-1. Wellbore with Fish (Forgenie et al., 1995) OMaurer Engineering Inc. 243. The operator decided to avoid multiple wireline runs to retrieve the wire fish. A CT strip-overoperation was designed that would allow constant well control throughout the recovery operations. The first step was to fish the end of the slickline with wireline. Then, a guide shoe was fabricatedfor stripping over the wire with CT (Figure 7-2).Anachedto CICoil Tubing Side View 0.108 Wire Top View Figure 7-2. Wire Guide Shoe (Forgenie et al., 1995)OMaurer Engineering Inc. 244. The wire was threaded through the shoe, out into the wellbore annulus and out through a special"Y" on the surface (Figure 7-3). 1 1 /2" Coil Tubing CTU Stuffing Box-Sceflold Work DeckFigure 7-3. CT Rig-Up for Fishing Wire (Forgenie et al., 1995) OMaurer Engineering Inc. 245. The CT was tripped in at 30 ft/min while pushing the go-devils to the rope socket (Figure 7-4).The wire was cut when the CT weight was set on the fish. Slickline 7 @ 10465PBTD 10383 Figure 7-4. Pushing Go-Devils to Stuck Shifting Tool(Forgenie et al., 1995) The operator then attempted to fish the go-devils and shifting tool with wireline. The top go-devilwas retrieved; the other fish were not. CT was then deployed to attempt the fishing job. However, ratherthan retrieving the fish, the CT pushed the tools into the tailpipe. Operations were halted since the toolswere now out of the way.Fishing operations were completed in 1% days; costs totaled about $25,000. Had a rig workoverbeen necessary to retrieve the tool and save the well, costs would have exceeded $500,000.7-4OMaurer Engineering Inc. 246. r" 72.BRITISH PETROLEUM (CT FISHING TOOL) British Petroleum successfully unstuck a string of CT with a new fishing tool (PEI Staff, 1996). The operator was evaluating a logging bypass plug when the plug became stuck on the adjustable spacer sub union below the packer (Figure 7-5, number 1). Several conventional approaches were tried without success.Figure 7-5. Fishing Tool to Unstick Bypass Plug(PEI staff, 1996) The new solution was to run a sleeve down the outside of the CT to centralize the top of the plug and direct it around the obstruction. A wrap-around sleeve was devised and pumped down using a wiper dart on top of the assembly (Figure 7-5, number 3). The CT string was run 50 ft past the hang-up point and placed in tension. The assembly was then pumped downhole. The string and bypass plug were retrieved successfully on the first attempt.+- - 7-5OMaurer Engineering Inc. 247. 73 .VIBRATION TECHNOLOGY (METHOD TO UNSTICK CT) Vibration Technology LLC (Bemat, 1998) described a resonant vibration system for unstickingCT and other tubulars. Three components form the resonating system (Figure 7-6): 1) a mechanicaloscillator, 2) a tubing string for transmitting vibration, and 3) a stuck fish to be freed.AECCENTRIC WEIGHT OSCILLATOR&---WORK S T R I N GSTUCK MEMBERFigure 7-6. Vibration System for Unsticking CT(Bernat, 1998)Vibration is generated by an eccentric-weight mechanical oscillator that produces axial sinusoidalforces that can be tuned to specific frequencies. At resonance, energy developed by the oscillator isefficiently transmitted to the stuck CT.OMaurer Engineering Inc. 248. The pipe oscillator (Figure 7-7) is attached to the CT above the injector by friction clamps. Theinjector remains in place to immediately recover the CT when it is freed. Figure 7-7. CT Oscillator (Bernat, 1998)Typical job duration for freeing CT is 1 day. Several case histories of freeing CT are summarizedin Table 7-1. TABLE 7-1. Fishing Successes with Vibrator (Bernat, 1998) Coil and BHA DcWl7-7OMaurer Engineering Inc. 249. 74 . REFERENCESBernat, Henry, 1998: "Coil Tubing Recovery Using Pipe Vibration Technology," published byVibration Technology LLC, Shreveport, Louisiana.Forgenie, V.H. et al., 1995: "Coiled Tubing Fishing Operations Utilize a First Time Techniqueto Strip Over and Recover 9500 Feet of Stuck Slickline Wire," SPE 30678, presented at the AnnualTechnical Conference and Exhibition, Dallas, Texas, October 22-25. PEI Staff, 1996: "Stuck Coiled Tubing Spawns New Fishing Tool," Petroleum EngineerInternational, March.OMaurer Engineering Inc. 250. 8. LoggingTABLE OF CONTENTS Page8. LOGGING . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .8-1 8.1 BPB WIRELINE SERVICES (CT-CONVEYED SLIM LOGGING TOOLS). . . . . . . . . 8-1 8.2 BP EXPLORATION (MEMORY LOGGING ON CT). . . . . . . . . . . . . . . . . . . . . . . . . . 8-5 8.3 CTES AND DREXEL (CT CABLE INSTALLATION) . . . . . . . . . . . . . . . . . . . . . . . . . . 8-5 8.4 HALLIBURTON ENERGY SERVICES (VIDEO SERVICES) . . . . . . . . . . . . . . . . . . . . 8-7 8.5 NOWSCO, ANDERSON, AND DOWNHOLE SYSTEMS (CONCENTRIC CT SYSTEM) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8-9 8.6 TRICO INDUSTRIES (JET PUMP FOR PRODUCTION LOGGING). . . . . . . . . . . . . 8- 10 8.7 REFERENCES. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8-12OMaurer Engineering Inc. 251. OMaurer Engineering Inc. 252. 8. Logging8.1 BPB WIRELINE SERVICES (CT-CONVEYED SLIM LOGGING TOOLS) BPB Wireline Services (Houpe, 1996) summarized the benefits and availability of slim loggingtools suited for use in horizontal wellbores. CT conveyance has been proven as generally superior tojointed-pipe methods. Lateral penetration limits resulting from buckling have been extended with largerCT and through various methods, including temporarily hanging small tubing or casing to the lowestvertical section of the well. A reduced diameter in the vertical section effectively reduces friction andextends horizontal penetration.BPB Wireline Services slim-hole logging tool line is based on the following generalspecifications: 2%-in. OD, 255F rating, and 12,500 psi rating. Oil-field slim tools include:RESISTIVITY:Array Induction SondeDual Laterolog SondeNUCLEAR:Dual Density/GR/CalipernDual-Neutron SondeACOUSTIC: Multichannel SonicAUXILIARY:CT AdaptorTension/Compression SubSlim Repeat Formation TesterFour-Arm Dipmeter Negotiating the curve with the logging string can be a significant obstacle/limitation for logginghorizontal wells. The rigid tool length for 2%-in. tools is plotted in the upper graph in Figure 8-1. Thelower graph is for conventional 3%-tools. A slim short logging tool string is preferred in most cases.Swivels, knuckles and cranks are also used to minimize effective string length. OMaurer Engineering Inc. 253. 2.25-INCH TOOLS Mold T o o l Length (ft)10 20 30 234 5 678 9 1 0 1 1 12 Rl~ldTool Length (rn)3.75-INCH TOOLS Mold T o o l Length (ft)10 20 30 234 5 6 709 101 1 12 RQld Tool Length (m) Note: For a given tool diameter, maxlmum build tool length (L) that will traverse a well of diameter (d) and bed radius (R) is given by: k2[(R+d)2-(R+t)2]1/2. Angular build rate (degreed30 meters)=171&aFigure 8-1. Maximum Tool Length Through a Curve (Houpe, 1996)BPB Wireline provided example logs from a job in Germany to illustrate the benefits of loggingin horizontal holes, even when significant offset vertical well data are available. In one case, a re-entrywas drilled on CT and logged with the same rig. Coil size was 23/8 inches. The logging tools were slightlysmaller than the tubing, resulting in an ideal situation with respect to buckling and lateral penetration. OMaurer Engineering Inc. 254. The dual-densitylgamma-raylcaliper traces from a slim horizontal sidetrack are shown inFigure 8-2. Several tight lens were found between 1792 and 1865 m. These barriers were blamed forpreviously observed pressure variations across the field.FILMUE: awrmm.crs nuc m: WIN ~a~mO( I ~ U * T - I P P ~ AT IS:U f M A I N LOG . .d Figure 8-2. Log from Horizontal Sidetrack (Houpe, 1996) OMaurer Engineering Inc. 255. Significant hydrocarbon deposits were revealed in the shaly sand analysis (Figure 8-3). The well-defined permeability barriers and faults were revealed in greater detail than expected. Figure 8-3. Lithology Log from Sidetrack (Houpe, 1996) OMaurer Engineering Inc. 256. 8.2 BP EXPLORATION (MEMORY LOGGING ON CT) fi Battery Holder Significant cost savings have been reported from PrudhoeBay by using memory logging tools on CT (Sas-Jaworsky andMemory SubBell, 1996) (Figure 8-4). Average costs were reportedly reduced Quarh Pressurealmost 50% for running logs in horizontal wells (from $38,500 to$1 9,800). Since no wireline is required, CT spool and surface Temperatureequipment requirements are greatly reduced. A standard string 17.1 ftCasing Collar Locator(1.69 in. OD)with five sensors can record data up to 22 hours at a sampling rateKnuckle Jointsof l/sec. Roller CentralizerThe principal disadvantage is lack of feedback on tool Gamma Rayfunction and/or damage. BP has tried to minimize the potentialfor damage by performing dummy runs with tool strings of similardimensions prior to running the logging string. &Roller Centralizer+Fullbore Flowmeter Figure 8-4. CT Memory LoggingBHA (Sas-Jaworsky and Bell, 1996)8.3 CTES AND DREXEL (CT CABLE INSTALLATION)CTES and Drexel (Newman et al., 1995) described the design of a CT wireline cable installationsystem that will install wireline inside CT while still on the reel. The new fixture greatly reduces the costof cable installation as compared to previous methods, which include: 1) hanging off CT in a vertical welland lowering the wireline inside, 2) laying the CT out horizontally and pumping the cable through, and3) installing a steel pull line inside the CT during manufacture, laying the CT out horizontally and pullingthe cable through. Each of these methods is expensive ($15,000 to $25,000). It has long been known that cable can be pumped out of CT by pumping water at high rates.Turbulence causes the cable to vibrate and so removes the friction element, allowing the cable to advancewith the flow. However, pumping cable into CT (Figure 8-5) is much more difficult due to the high pumppressure at the point the cable enters the system. Injection force (analogous to snubbing a string into ahigh-pressure well) is required to introduce the cable. OMaurer Engineering Inc. 257. Returned Fluid to Storage Tank PumpedWireline Pressure Control HeadI "Stuffing Box"Wireline SpoolCoiled Tubing Reel -Figure 1 Pumping Cable into CT Figure 8-5. Pumping Cable into CT (Newman et al., 1995) A cable injector was required for this design. Several concepts were devised and considered(Figure 8-6). The approach adopted for the final design was a capstan wheel inside a pressure housing. High PressurePressure Housing Hi h Pressure Fluid lnlel fluid lnlet very long PoweredRollersRoller InjectorFlow Tube InjectorEnclosed Wireline SpoolHi h Pressurefluid Inlet Stationary Traveling SlipsSlipsWheel Snubbing InjectorTractor InjectorCapstan injectorFigure 8-6. Potential Concepts for Injecting Cable(Newman et al., 1995)OMaurer Engineering Inc. 258. ---The cable injection system design is shown in Figure 8-7. The wireline spool can be rotated abouta vertical axis due to the need to remove torque from used cable. A storage tank is used so that the watercan be cooled between pump trips through the CT.Spoollng SkidHlgh Prossure Pumping Unit;--- Figure 8-7. Cable Injection System for CT (Newman et al., 1995)8.4 HALLIBURTON ENERGY SERVICES (VIDEO SERVICES)Halliburton Energy Services (Maddox and Gibling, 1995) described several applications fordownhole video services that allow planning conformance technology treatments, monitoring the treatmentin progress, and confirming success after the treatment is complete. A video survey is especially usehlfor observing casing integrity and finding holes, cracks or corroded areas. Fluid entry or exit can also beobserved at these areas (Figure 8-8).OMaurer Engineering Inc. 259. CASING ERODED BY WATER INFLOW WATER ENTRY Figure 8-8. Video Log Showing Casing Condition(Maddox and Gibling, 1995)Video logs can also be used for types of production profiles. Video can be analyzed along withspinner data to estimate relative contributions of each section of the wellbore. Plotting observed influxesversus depth produces a video production profile (Figure 8-9).PERFS FDSPINNER TEMPVIDEO ANALYSIS REPERF I IFLUID I SPINNER 2